Apparatus and method for pumping fluid in a borehole

ABSTRACT

A method to manipulate a well, comprising running an apparatus having a container and an electrically powered pump into the well. The well is isolated, and a wireless control signal, such as an electromagnetic or acoustic signal, is sent to operate the pump in response in order to pump fluid from within the container to the surrounding portion of the well. The apparatus may comprise a pressure balancing means, such as a floating piston between two ports of the container, and/or an in well charging means.

This invention relates to an apparatus and method for pumping fluid in aborehole or well.

Boreholes are commonly drilled for a variety of reasons in the oil andgas industry, not least to function as wells to recover hydrocarbons,but also as test wells, observation wells or injection wells.

On occasion, it may be necessary to deploy fluid into the well. Forexample, an acid treatment may be conducted where a chemical, oftenhydrochloric acid based, is deployed in a well in order to remove ormitigate blockages or potential blockages, such as scale, in the well.This can also be used to treat perforations in the well.

In order to deploy the acid treatment, fluid may be pumped from surfacethrough the tubing. However this may not accurately direct the fluid tothe specific area of the well or formation required.

In order to more accurately deploy fluid into a required area of thewell, coiled tubing may be used. A 2″ diameter coiled tube, for example,can be deployed into the well. The acid treatment is then pumped downthe tube and exits into the well at the appropriate area.

Whilst generally satisfactory, the inventors of the present inventionhave noted that deploying fluids in such a manner can be capitalintensive requiring considerable rig time and large volumes of fluid.When using coiled tubing, many thousands of feet is often required(depending on the well depth). Moreover it is a time-consuming processto launch the coiled tubing, deploy the fluid, and then recover thecoiled tubing. Sometimes coiled tubing cannot access parts of the welldue to the configuration of the bottom hole assembly, and may not beable to deploy the fluid to the particular area intended.

A number of other fluids may be deployed in a well, such as a tracer orbreaker fluid.

Hydraulic fracturing or various pressure tests, such as an intervalinjectivity test and a permeability test, can also be carried out usingpressure applied from surface. However certain portions of the well maybe isolated from the surface, or it may not be possible to isolatecertain portions of the well from other portions, whilst maintainingpressure connection to the surface.

The inventors of the present invention have sought to mitigate one ormore of the problems of the prior art.

According to a first aspect of the present invention, there is provideda method to manipulate a well, comprising:

-   -   providing an apparatus, the apparatus comprising:        -   a container having a volume of at least 1 litre;        -   a port to allow fluid communication between a portion of the            container and the surrounding portion of the well;        -   an electrically powered pump configured to direct fluids            to/from the container from/to the surrounding portion of the            well;        -   a battery to supply electrical power to the pump;        -   a control mechanism to control the pump comprising a            communication device configured to receive a control signal            for operating the pump;    -   running the apparatus into the well;    -   optionally isolating the port of the apparatus from a surface of        the well;    -   sending a control signal to the communication device at least in        part by a wireless control signal transmitted in at least one of        the following forms: electromagnetic, acoustic, inductively        coupled tubulars and coded pressure pulsing;    -   operating the pump in response to said control signal and        optionally pumping fluid from within the container to the        surrounding portion of the well.

As described in more detail below, the apparatus may include a wirelesscommunication device and/or a floating piston within the container (forexample to pressure balance or for charging).

Thus, according to a second aspect, the present invention also providesan apparatus comprising:

-   -   a container having a volume of at least 1 litre;    -   a port to allow fluid communication between a portion of the        container and the surrounding portion of the well;    -   an electrically powered pump configured to direct fluids to/from        the container from/to the surrounding portion of the well;    -   a battery to supply electrical power to the pump;    -   a control mechanism to control the pump comprising a        communication device configured to receive a control signal for        operating the pump, said communication device being a wireless        communication device; and,    -   a floating piston or bladder in the container.

The pump may be provided at the port.

Often, the pump is operated to pump fluid from within the container tothe surrounding portion of the well. Often this is at least one litre ormore than five litres of fluid which has been added to the container atthe surface before the apparatus is run into the well. This fluid may beused to treat the well/reservoir.

The electrical pump is preferably a positive displacement pump such as apiston pump, gear type pump, screw pump, diaphragm, lobe pump;especially a piston or gear pump. Alternatively the pump may be avelocity pump such as a centrifugal pump.

The pump may be operable to pump fluids at a rate of 0.01 cc/s to 20cc/s.

The pump operation or rate can be controlled in response to a furthercontrol signal being received by the wireless communication device (orthis may be an instruction in the original signal).

The step of sending a control signal to the communication device isnormally after the step of isolating the port of the apparatus from thewell but for certain embodiments, it may be before.

The entire apparatus, and not just the port of the apparatus, may beisolated from the surface of the well.

Isolating the port of the apparatus from the surface of the well meanspreventing pressure or fluid communication between the port and thesurface of the well.

Isolation can be achieved using the well infrastructure and isolatingcomponents. Isolating components comprise packers, plugs such as bridgeplugs, valves, and/or the apparatus. In contrast, well infrastructurecomprises cement in an annulus, casing and/or other tubulars. In certainembodiments, more than one isolating component can isolate the port ofthe apparatus from the surface of the well. For example, a packer may beprovided in an annulus and a valve provided in a central tubing andtogether they isolate the port of the apparatus from the surface of thewell. In such cases the uppermost extent of the well section thatcontains the port of the apparatus is defined by the uppermost isolatingcomponent.

Isolating the port of the apparatus from the surface of the wellinvolves isolating the section of the well containing the port downhole,such that the uppermost isolating component in that isolated wellsection is at least 100 m from the surface of the well, optionally atleast 250 m, or at least 500 m.

The port of the apparatus is typically at least 100 m from the uppermostisolating component in the same section of the well. In certainembodiments, the port of the apparatus is at most 500 m from theuppermost isolating component in the same section of the well,optionally at most 200 m therefrom.

The well or a section thereof may be shut in, at surface or downhole,after the apparatus has been run and before operating the pump.

The step of isolating the port of the apparatus from the surface of thewell may include shutting in at least a section of the well. For examplethe well can be shut in above the port of the apparatus, which isolatesthe port of the apparatus from the surface of the well.

For other embodiments at least a section of the well can be shut inseparate to this isolating step, for example, below the apparatus, orthe well may have been shut in at an earlier date.

Isolating the port of the apparatus from the surface of the well, andoptionally shutting in the well, can reduce the volume exposed to theapparatus which then focuses the released fluid to the intended area.

The isolating components may be upper isolating components, and lowerisolating components may be used to isolate a section of the well from afurther section therebelow.

Thus embodiments of the present invention allow the release of fluids ina lower isolated section of a well where it may not have hitherto beenpossible, convenient or indeed safe to do so using conventional meanssuch as fluid control lines to surface.

The well may be a production well.

Pressure Balancing Means

The apparatus may comprise a pressure balancing means. The port may be afirst port, and a second port may be provided in the apparatus betweenthe container and a surrounding portion of the well, the first andsecond ports separated within the apparatus by a pressure balancingdevice such as a bladder or a floating piston.

In a first embodiment with a pressure balancing means, the pump isnormally provided at one of the ports (preferably the first port), thefluid being pumped to/from the container is provided between thefloating piston and said first port. An opposite side of the floatingpiston is exposed to well pressure via the second port, thus balancingthe pressure on both sides of the floating piston.

In a second embodiment with a pressure balancing means, the pump isprovided between said floating piston and the first port and a secondfloating piston is provided between the pump and the first port. Thepump is thus between the two floating pistons. The first floating pistonfunctions as a pressure balancing means and the second floating pistoncontrols fluid ingress/egress from the container through the first port.A control fluid is provided in the container, between the respectivefloating pistons, and this control fluid can be pumped by the pump,which in turn causes the second floating piston to move and direct fluidto be expelled or drawn into the container, between the first port andthe second floating piston.

The second embodiment is particularly suited for apparatus where fluidcan be both expelled and drawn in (in either order) since the pump isoperating on a controlled fluid.

For embodiments with pressure balancing means, the pump can then directfluids in or out of the container with less or with no requirement toovercome a pressure differential between the container and thesurrounding portion of the well.

Pressure balancing means is not essential. Embodiments used for barriertesting from below a barrier may especially be used without one.Nevertheless, in such a case, it is preferred to have a small (variable)amount of gas at, for example, more than 100 psi, within the containerto stop the pump acting against a vacuum. Indeed, a higher pressure,such as over 1000 psi also helps the pump operate.

In any case, the pump can pump the fluid directly i.e. the fluid movingto/from the surrounding portion of the well to the container; orindirectly for example the control fluid which acts on the fluid movingto/from the surrounding portion of the well indirectly, for example viaa floating piston, to the container.

Pump Options

The electrical pump may drive another pump which in turn moves the fluidto/from the container from/to the surrounding portion of the well. Thissecond pump need not be electrical; rather the ‘prime mover’ iselectrical.

The pump may comprise a piston with a motorised lead screw option, akinto a syringe.

A single stroke of such a piston or lead screw may be sufficient incertain applications, although for other applications the piston isreciprocated.

This single stroke option is particularly suited to smaller volumeapplications (for example up to 5 litres) and also where either side ofthe piston is pressure balanced with the well.

In other embodiments, pumps with a piston or lead screw are reciprocatedmultiple times, such as reciprocated at least five times or for certainapplications hundreds of times or many more times.

For applications where the piston is reciprocated, the piston stroke maysweep the volume of the container. Alternatively, also for reciprocatedpistons, the piston may draw fluid from or expel fluid to a furtherchamber within the apparatus. The further chamber may be many times,such as at least two times, larger than the volume that the pistonstroke sweeps.

The pump can function as a meter and so monitor the volume of fluidtravelling to/from the container from/to the surrounding portion of thewell. For example the apparatus can count the reciprocations of thepump, and using the volume of the pump, calculate the amount of fluidbeing moved.

Valves

The apparatus may comprise a mechanical valve assembly which normallyhas a valve member. The valve may be integral to the pump especiallywhere the mechanical valve assembly comprises a check valve.

Alternatively it may be driven by the control mechanismelectro-mechanically, or electro-hydraulically via porting.

The mechanical valve assembly may be at one end of the apparatus,especially at one of the ports. However it may be in its central body.One may be provided at each end.

The valve may resist fluid entry or may resist fluid exit from thecontainer, depending on whether the pump is intended to expel or drawfluids in.

A choke may be integrated with the mechanical valve assembly or it maybe in a flowpath comprising one of the ports and the mechanical valveassembly. The valve member may function as a choke. Where a plurality ofvalve members are provided, multiple different sizes of chokes may beprovided. Thus, for certain embodiments, the mechanical valve assemblycomprises a variable valve member, which itself can function as a chokeand indeed it can be varied in situ (that is, in the well). For example,a choke disk may be used, which may be rotatably mounted with differentsizes of apertures to provide a variable choking means.

Outlet Tube

The first port may comprise a tube with a plurality of openings. Nozzlescan also be provided in order to direct its effects towards thecommunication paths for example.

The openings, for example at least three, may be spaced apart from eachother in the same direction as the well, for example in a directionsubstantially parallel to the well, or in a spiral shape, the shapehaving an axis also generally parallel to the well. The tube may be asmall diameter tube (for example ¼-¾″ outer diameter), which may extendover the communication paths. A rotating inner/outer sleeve or othermeans may be used to selectively open or close the openings.

There may be a plurality of valve members, optionally controllingopenings of different sizes and/or at different locations. Eachdifferent valve member may be independently controlled or two or moregroups of openings may be controlled by separate valves. For example,groups of openings may be provided on a separate tube, each group beingcontrolled by a valve. The method may then direct the fluid to aparticular area.

Container Options

The apparatus may be elongate in shape. It may be in the form of a pipe.It is normally cylindrical in shape.

Whilst the size of the container can vary, depending on the nature ofthe well in which it will be used, the container may have a volume of atleast 5 litres (l), optionally at least 50 l or optionally at least 100l. The container may have a volume of at most 3000 l, normally at most1500 l, optionally at most 500 l.

Thus the apparatus may comprise a pipe/tubular (or a sub in part of apipe/tubular) housing the container and other components or indeed thecontainer may be made up of tubulars, such as tubing, drill pipe, lineror casing joined together. The tubulars may comprise joints each with alength of from 3 m to 14 m, generally 8 m to 12 m, and nominal externaldiameters of from 2⅜″ (or 2⅞″) to 7″.

References to ‘casing’ includes ‘liner’ unless stated otherwise.

The apparatus may be configured to pump at least 1 litre, optionally atleast 5 litres, optionally at least 10 litres, more optionally at least50 litres of fluid to/from the container from/to an outside thereof.

Secondary Containers

In addition to the container (sometimes referred to below as a ‘primarycontainer’) there may be one or more secondary containers, optionallyeach with respective control devices controlling fluid communicationbetween the respective secondary container and the surrounding portionof the well or other portion of the apparatus.

The control devices of the secondary containers may include pumps,mechanical valves and/or latch assemblies.

A piston may be provided in one or more of the secondary containers. Itmay, for certain embodiments, function as the valve.

Alternatively, a floating piston may be controlled indirectly by thecontrol device such as the valve. In some embodiments, the piston may bedirectly controlled by the latch assembly.

The latch assembly can control the floating piston—it can hold thefloating piston in place against action of other forces (for examplewell pressure) and is released in response to an instruction from thecontrol mechanism.

Thus a secondary container can have a mechanical valve assembly (such asthose described herein) or latch assembly, rather than a pump, whichregulates fluid communication between that secondary container and asurrounding portion of the well. The control device may or may not beprovided at a port.

Thus there may be one, two, three or more than three secondarycontainers. The further control devices for the secondary containers mayor may not move in response to a control signal, but may instead respondbased on a parameter or time delay. Each control device for therespective secondary container can be independently operable. A commoncommunication device may be used for sending a control signal to aplurality of control devices.

The contents of the containers may or may not be miscible at the outlet.For example one container can have a polymer and a second container across linker, when mixed, in use, in the well form a gel or otherwiseset/cure. The containers can be configured differently, for example havedifferent volumes or chokes etc.

The containers may have a different internal pressure compared to thepressure of the surrounding portion of the well. If less than asurrounding portion of the well, they are referred to as ‘underbalanced’and when more than a surrounding portion of the well they are referredto as ‘overbalanced’.

Thus (an) underbalanced or overbalanced secondary container(s) andassociated secondary port and control device may be provided, thesecondary container(s) each preferably having a volume of at least fivelitres and, in use, having a pressure lower/higher than the surroundingportion of the well normally for at least one minute, before the controldevice is activated optionally in response to the control signal. Fluidssurrounding the secondary container can thus be drawn in (forunderbalanced containers), optionally quickly, or fluids expelled (foroverbalanced containers).

Thus, a plurality of primary and/or secondary containers or apparatusmay be provided each having different functions, the primary containerbeing controlled by a pump, one or more secondary containers may beunderbalanced and one or more secondary containers may be overbalanced.

This can be useful, for example, to partially clear a filter cake usingan underbalanced container, before deploying an acid treatment onto theperforations using the container controlled by a pump.

Alternatively, for a short interval manipulation, a skin barrier couldbe removed from the interval by an underbalanced container, and/or byacid release from an overbalanced container; and then the apparatusincluding the pump can be used to pump fluid from the interval.

Fluid from a first chamber within the container can go into another tomix before being released/expelled.

Other Apparatus Options

In addition to the control signal, the apparatus may includepre-programmed sequences of actions, for example a pump starting andstopping, or a change in valve member position; based on parameters forexample time, pressure detected or not detected or detection ofparticular fluid or gas. For example, under certain conditions, theapparatus will perform certain steps sequentially—each subsequent stepfollowing automatically. This can be beneficial where a delay to waitfor a signal to follow on could mitigate the usefulness of theoperation.

The apparatus may have a mechanism to orientate it rotationally.

Normally the ports are provided on a side face of the apparatus althoughcertain embodiments can have the ports provided in an end face.

Annular Sealing Device

The apparatus may be provided in the well below an annular sealingdevice, the annular sealing device engaging with an inner face of casingor wellbore in the well, and being at least 100 m below a surface of thewell.

For certain embodiments, the annular sealing device is one of theisolating components.

A connector is optionally also provided connecting the apparatus to theannular sealing device, the connector being above the apparatus andbelow the annular sealing device.

The control signal may be sent from above the annular sealing device tothe apparatus below the annular sealing device often in its wirelessform.

The annular sealing device may be at least 300 m from the surface of thewell. The surface of the well is the top of the uppermost casing of thewell. The annular sealing device is a device which seals between twotubulars (or a tubular and the wellbore), such as a packer element or apolished bore and seal assembly. The packer element may be part of apacker, bridge plug, or liner hanger, especially a packer or bridgeplug.

A packer includes a packer element along with a packer upper tubular anda packer lower tubular along with a body on which the packer element ismounted.

The packer can be permanent or temporary. Temporary packers are normallyretrievable and are run with a string and so removed with the string.Permanent packers on the other hand, are normally designed to be left inthe well (though they could be removed at a later time).

A sealing portion of the annular sealing device may be elastomeric,non-elastomeric and/or metallic.

It can be difficult to control apparatus in the area below an annularsealing device between a casing/wellbore and an inner production tubingor test string, especially independent of the fluid column in the innerproduction tubing. Thus embodiments of the present invention can providea degree of control in this area, through the combination of the pumpand the wireless control.

This annular sealing device(s) may be wirelessly controlled. Thus whereappropriate, they may be expandable and/or retractable by wirelesssignals.

In some embodiments, kill fluid may be present inside tubing in the wellabove the annular sealing device before the apparatus is activated.

Connector

The connector is a mechanical connection (as opposed to a wirelessconnection) and may comprise, at least in part, a tubular connection forexample some lengths of tubing or drill pipe. It may include one or moreof perforation guns, gauge carriers, cross-overs, subs and valves. Theconnector may comprise or consist of a threaded connection. Theconnector does not consist of only wireline, and normally does notinclude it.

Normally the connector comprises a means to connect to the annularsealing device, such as a thread or dogs.

The connector may be within the same casing that the annular sealingdevice is connected to.

The connector may comprise a plug for example in the tubing (which isseparate from the annular sealing device which may also comprise aplug).

The control signal may be sent from above the annular sealing device.

Signals

The wireless control signal is transmitted in at least one of thefollowing forms: electromagnetic, acoustic, inductively coupled tubularsand coded pressure pulsing and references herein to “wireless”, relateto said forms, unless where stated otherwise.

The signals may be data or command signals which need not be in the samewireless form. Accordingly, the options set out herein for differenttypes of wireless signals are independently applicable to data andcommand signals. The control signals can control downhole devicesincluding sensors. Data from sensors may be transmitted in response to acontrol signal. Moreover data acquisition and/or transmissionparameters, such as acquisition and/or transmission rate or resolution,may be varied using suitable control signals.

The communication device may comprise a wireless communication device.In alternative embodiments, the communication device is a wiredcommunication device and the wireless signal transmitted in other partsof the well.

Coded Pressure Pulses

Pressure pulses include methods of communicating from/to within thewell/borehole, from/to at least one of a further location within thewell/borehole, and the surface of the well/borehole, using positiveand/or negative pressure changes, and/or flow rate changes of a fluid ina tubular and/or annular space.

Coded pressure pulses are such pressure pulses where a modulation schemehas been used to encode commands and/or data within the pressure or flowrate variations and a transducer is used within the well/borehole todetect and/or generate the variations, and/or an electronic system isused within the well/borehole to encode and/or decode commands and/orthe data. Therefore, pressure pulses used with an in-well/boreholeelectronic interface are herein defined as coded pressure pulses. Anadvantage of coded pressure pulses, as defined herein, is that they canbe sent to electronic interfaces and may provide greater data rateand/or bandwidth than pressure pulses sent to mechanical interfaces.

Where coded pressure pulses are used to transmit control signals,various modulation schemes may be used to encode control signals such asa pressure change or rate of pressure change, on/off keyed (OOK), pulseposition modulation (PPM), pulse width modulation (PWM), frequency shiftkeying (FSK), pressure shift keying (PSK), amplitude shift keying (ASK),combinations of modulation schemes may also be used, for example,OOK-PPM-PWM. Data rates for coded pressure modulation schemes aregenerally low, typically less than 10 bps, and may be less than 0.1 bps.

Coded pressure pulses can be induced in static or flowing fluids and maybe detected by directly or indirectly measuring changes in pressureand/or flow rate. Fluids include liquids, gasses and multiphase fluids,and may be static control fluids, and/or fluids being produced from orinjected in to the well or a section thereof, for example when it is notisolated from the surface of the well.

Signals—General

Preferably the wireless signals are such that they are capable ofpassing through a barrier, such as a plug or said annular sealingdevice, when fixed in place, and therefore preferably able to passthrough the isolating components. Preferably therefore the wirelesssignals are transmitted in at least one of the following forms:electromagnetic, acoustic, and inductively coupled tubulars.

EM/Acoustic and coded pressure pulsing use the well, borehole orformation as the medium of transmission. The EM/acoustic or pressuresignal may be sent from the well, or from the surface. If provided inthe well, an EM/acoustic signal can travel through any annular sealingdevice, although for certain embodiments, it may travel indirectly, forexample around any annular sealing device.

Electromagnetic and acoustic signals are especially preferred—they cantransmit through/past an annular sealing device without specialinductively coupled tubular infrastructure, and for data transmission,the amount of information that can be transmitted is normally highercompared to coded pressure pulsing, especially receiving data from thewell.

Therefore, the communication device may comprise an acousticcommunication device and the wireless control signal comprises anacoustic control signal and/or the communication device may comprise anelectromagnetic communication device and the wireless control signalcomprises an electromagnetic control signal.

Similarly the transmitters and receivers used correspond with the typeof wireless signals used. For example an acoustic transmitter andreceiver are used if acoustic signals are used.

Where inductively coupled tubulars are used, there are normally at leastten, usually many more, individual lengths of inductively coupledtubular which are joined together in use, to form a string ofinductively coupled tubulars. They have an integral wire and may beformed tubulars such as tubing, drill pipe or casing. At each connectionbetween adjacent lengths there is an inductive coupling.

The inductively coupled tubulars that may be used can be provided by N OV under the brand Intellipipe®.

Thus, the EM/acoustic or pressure wireless signals can be conveyed arelatively long distance as wireless signals, sent for at least 200 m,optionally more than 400 m or longer which is a clear benefit over othershort range signals. Embodiments including inductively coupled tubularsprovide this advantage/effect by the combination of the integral wireand the inductive couplings. The distance travelled may be much longer,depending on the length of the well.

Data and commands within the signal may be relayed or transmitted byother means. Thus the wireless signals could be converted to other typesof wireless or wired signals, and optionally relayed, by the same or byother means, such as hydraulic, electrical and fibre optic lines. In oneembodiment, the signals may be transmitted through a cable for a firstdistance, such as over 400 m, and then transmitted via acoustic or EMcommunications for a smaller distance, such as 200 m. In anotherembodiment they are transmitted for 500 m using coded pressure pulsingand then 1000 m using a hydraulic line.

Thus whilst non-wireless means may be used to transmit the signal inaddition to the wireless means, preferred configurations preferentiallyuse wireless communication. Thus, whilst the distance travelled by thesignal is dependent on the depth of the well, often the wireless signal,including relays but not including any non-wireless transmission, travelfor more than 1000 m or more than 2000 m. Preferred embodiments alsohave signals transferred by wireless signals (including relays but notincluding non-wireless means) at least half the distance from thesurface of the well to the apparatus.

Different wireless signals may be used in the same well forcommunications going from the well towards the surface, and forcommunications going from the surface into the well.

Thus, the wireless signal may be sent to the communication device,directly or indirectly, for example making use of in-well relays aboveand/or below any annular sealing device. The wireless signal may be sentfrom the surface or from a wireline/coiled tubing (or tractor) run probeat any point in the well optionally above any annular sealing device.For certain embodiments, the probe may be positioned relatively close toany annular sealing device for example less than 30 m therefrom, or lessthan 15 m.

Acoustic

Acoustic signals and communication may include transmission throughvibration of the structure of the well including tubulars, casing,liner, drill pipe, drill collars, tubing, coil tubing, sucker rod,downhole tools; transmission via fluid (including through gas),including transmission through fluids in uncased sections of the well,within tubulars, and within annular spaces; transmission through staticor flowing fluids; mechanical transmission through wireline, slicklineor coiled rod; transmission through the earth; and transmission throughwellhead equipment. Communication through the structure and/or throughthe fluid are preferred.

Acoustic transmission may be at sub-sonic (<20 Hz), sonic (20 Hz−20kHz), and ultrasonic frequencies (20 kHz−2 MHz). Preferably the acoustictransmission is sonic (20 Hz−20 khz).

The acoustic signals and communications may include Frequency ShiftKeying (FSK) and/or Phase Shift Keying (PSK) modulation methods, and/ormore advanced derivatives of these methods, such as Quadrature PhaseShift Keying (QPSK) or Quadrature Amplitude Modulation (QAM), andpreferably incorporating Spread Spectrum Techniques. Typically they areadapted to automatically tune acoustic signalling frequencies andmethods to suit well conditions.

The acoustic signals and communications may be uni-directional orbi-directional. Piezoelectric, moving coil transducer ormagnetostrictive transducers may be used to send and/or receive thesignal.

EM

Electromagnetic (EM) (sometimes referred to as Quasi-Static (QS))wireless communication is normally in the frequency bands of: (selectedbased on propagation characteristics)

-   -   sub-ELF (extremely low frequency) <3 Hz (normally above 0.01        Hz);    -   ELF 3 Hz to 30 Hz;    -   SLF (super low frequency) 30 Hz to 300 Hz;    -   ULF (ultra low frequency) 300 Hz to 3 kHz; and,    -   VLF (very low frequency) 3 kHz to 30 kHz.

An exception to the above frequencies is EM communication using the pipeas a waveguide, particularly, but not exclusively when the pipe is gasfilled, in which case frequencies from 30 kHz to 30 GHz may typically beused dependent on the pipe size, the fluid in the pipe, and the range ofcommunication. The fluid in the pipe is preferably non-conductive.

U.S. Pat. No. 5,831,549 describes a telemetry system involving gigahertztransmission in a gas filled tubular waveguide.

Sub-ELF and/or ELF are preferred for communications from a well to thesurface (for example over a distance of above 100 m). For more localcommunications, for example less than 10 m, VLF is preferred. Thenomenclature used for these ranges is defined by the InternationalTelecommunication Union (ITU).

EM communications may include transmitting communication by one or moreof the following: imposing a modulated current on an elongate member andusing the earth as return; transmitting current in one tubular andproviding a return path in a second tubular; use of a second well aspart of a current path; near-field or far-field transmission; creating acurrent loop within a portion of the well metalwork in order to create apotential difference between the metalwork and earth; use of spacedcontacts to create an electric dipole transmitter; use of a toroidaltransformer to impose current in the well metalwork; use of aninsulating sub; a coil antenna to create a modulated time varyingmagnetic field for local or through formation transmission; transmissionwithin the well casing; use of the elongate member and earth as acoaxial transmission line; use of a tubular as a wave guide;transmission outwith the well casing.

Especially useful is imposing a modulated current on an elongate memberand using the earth as return; creating a current loop within a portionof the well metalwork in order to create a potential difference betweenthe metalwork and earth; use of spaced contacts to create an electricdipole transmitter; and use of a toroidal transformer to impose currentin the well metalwork.

To control and direct current advantageously, a number of differenttechniques may be used. For example one or more of: use of an insulatingcoating or spacers on well tubulars; selection of well control fluids orcements within or outwith tubulars to electrically conduct with orinsulate tubulars; use of a toroid of high magnetic permeability tocreate inductance and hence an impedance; use of an insulated wire,cable or insulated elongate conductor for part of the transmission pathor antenna; use of a tubular as a circular waveguide, using SHF (3 GHzto 30 GHz) and UHF (300 MHz to 3 GHz) frequency bands.

Suitable means for receiving the transmitted signal are also provided,these may include detection of a current flow; detection of a potentialdifference; use of a dipole antenna; use of a coil antenna; use of atoroidal transformer; use of a Hall effect or similar magnetic fielddetector; use of sections of the well metalwork as part of a dipoleantenna.

Where the phrase “elongate member” is used, for the purposes of EMtransmission, this could also mean any elongate electrical conductorincluding: liner; casing; tubing or tubular; coil tubing; sucker rod;wireline; drillpipe; slickline or coiled rod.

A means to communicate signals within a well with electricallyconductive casing is disclosed in U.S. Pat. No. 5,394,141 by Soulier andU.S. Pat. No. 5,576,703 by MacLeod et al both of which are incorporatedherein by reference in their entirety. A transmitter comprisingoscillator and power amplifier is connected to spaced contacts at afirst location inside the finite resistivity casing to form an electricdipole due to the potential difference created by the current flowingbetween the contacts as a primary load for the power amplifier. Thispotential difference creates an electric field external to the dipolewhich can be detected by either a second pair of spaced contacts andamplifier at a second location due to resulting current flow in thecasing or alternatively at the surface between a wellhead and an earthreference electrode.

Relay

A relay comprises a transceiver (or receiver) which can receive asignal, and an amplifier which amplifies the signal for the transceiver(or a transmitter) to transmit it onwards.

There may be at least one relay. The at least one relay (and thetransceivers or transmitters associated with the apparatus or at thesurface) may be operable to transmit a signal for at least 200 m throughthe well. One or more relays may be configured to transmit for over 300m, or over 400 m.

For acoustic communication there may be more than five, or more than tenrelays, depending on the depth of the well and the position of theapparatus.

Generally, less relays are required for EM communications. For example,there may be only a single relay. Optionally therefore, an EM relay (andthe transceivers or transmitters associated with the apparatus or at thesurface) may be configured to transmit for over 500 m, or over 1000 m.

The transmission may be more inhibited in some areas of the well, forexample when transmitting across a packer. In this case, the relayedsignal may travel a shorter distance. However, where a plurality ofacoustic relays are provided, preferably at least three are operable totransmit a signal for at least 200 m through the well.

For inductively coupled tubulars, a relay may also be provided, forexample every 300-500 m in the well.

The relays may keep at least a proportion of the data for laterretrieval in a suitable memory means.

Taking these factors into account, and also the nature of the well, therelays can therefore be spaced apart accordingly in the well.

The control signals may cause, in effect, immediate activation, or maybe configured to activate the apparatus after a time delay, and/or ifother conditions are present such as a particular pressure change.

Electronics

The apparatus may comprise at least one battery optionally arechargeable battery. The battery may be at least one of a hightemperature battery, a lithium battery, a lithium oxyhalide battery, alithium thionyl chloride battery, a lithium sulphuryl chloride battery,a lithium carbon-monofluoride battery, a lithium manganese dioxidebattery, a lithium ion battery, a lithium alloy battery, a sodiumbattery, and a sodium alloy battery. High temperature batteries arethose operable above 85° C. and sometimes above 100° C. The batterysystem may include a first battery and further reserve batteries whichare enabled after an extended time in the well. Reserve batteries maycomprise a battery where the electrolyte is retained in a reservoir andis combined with the anode and/or cathode when a voltage or usagethreshold on the active battery is reached.

The control mechanism is normally an electronic control mechanism andthe communication device is normally an electronic communication device.

The battery and optionally elements of the control electronics may bereplaceable without removing tubulars. They may be replaced by, forexample, using wireline or coiled tubing. The battery may be situated ina side pocket.

The apparatus, especially the control mechanism, preferably comprises amicroprocessor. Electronics in the apparatus, to power variouscomponents such as the microprocessor, control and communicationsystems, and optionally the valve, are preferably low power electronics.Low power electronics can incorporate features such as low voltagemicrocontrollers, and the use of ‘sleep’ modes where the majority of theelectronic systems are powered off and a low frequency oscillator, suchas a 10-100 kHz, for example 32 kHz, oscillator used to maintain systemtiming and ‘wake-up’ functions. Synchronised short range wireless (forexample EM in the VLF range) communication techniques can be usedbetween different components of the system to minimize the time thatindividual components need to be kept ‘awake’, and hence maximise‘sleep’ time and power saving.

The low power electronics facilitates long term use of variouscomponents of the apparatus. The control mechanism may be configured tobe controllable by the control signal up to more than 24 hours afterbeing run into the well, optionally more than 7 days, more than 1 month,or more than 1 year or up to 5 years. It can be configured to remaindormant before and/or after being activated.

Sensors

The apparatus and/or the well (above and/or especially below the annularsealing device) may comprise at least one pressure sensor. The pressuresensor may be below the annular sealing device and may or may not formpart of the apparatus. It can be coupled (physically or wirelessly) to awireless transmitter and data can be transmitted from the wirelesstransmitter to above the annular sealing device or otherwise towards thesurface. Data can be transmitted in at least one of the following forms:electromagnetic, acoustic, inductively coupled tubulars especiallyacoustic and/or electromagnetic as described herein above.

Such short range wireless coupling may be facilitated by EMcommunication in the VLF range.

Optionally the apparatus comprises a volume or level indicator such asan empty/full indicator or a proportional indicator arranged todetermine the volume or level of fluid in the container. A means torecover the data from the volume indicator is also normally included.The apparatus may comprise a pressure gauge, arranged to measureinternal pressure in the container. The communication device may beconfigured to send signals from the pressure gauge optionallywirelessly.

Preferably at least temperature and pressure sensors are provided. Avariety of sensors may be provided, including acceleration, vibration,torque, movement, motion, radiation, noise, magnetism, corrosion;chemical or radioactive tracer detection; fluid identification such ashydrate, wax and sand production; and fluid properties such as (but notlimited to) flow, density, water cut, for example by capacitance andconductivity, pH and viscosity. Furthermore the sensors may be adaptedto induce the signal or parameter detected by the incorporation ofsuitable transmitters and mechanisms. The sensors may also sense thestatus of other parts of the apparatus or other equipment within thewell, for example valve member position or motor rotation of the pump.

An array of discrete temperature sensors or a distributed temperaturesensor can be provided (for example run in) with the apparatus.Optionally therefore it may be below the annular sealing device. Thesetemperature sensors may be contained in a small diameter (for example¼″) tubing line and may be connected to a transmitter or transceiver. Ifrequired any number of lines containing further arrays of temperaturesensors can be provided. This array of temperature sensors and thecombined system may be configured to be spaced out so the array oftemperature sensors contained within the tubing line may be alignedacross the formation, for example the communication paths; either forexample generally parallel to the well, or in a helix shape.

The array of discrete temperature sensors may be part of the apparatusor separate from it.

The temperature sensors may be electronic sensors or may be a fibreoptic cable.

Therefore in this situation the additional temperature sensor arraycould provide data from the communication path interval(s) and indicateif, for example, communication paths are blocked/restricted. The arrayof temperature sensors in the tubing line can also provide a clearindication of fluid flow, particularly when the apparatus is activated.Thus for example, more information can be gained on the response of thecommunication paths—an upper area of communication paths may have beenopened and another area remain blocked and this can be deduced by thelocal temperature along the array of the temperature sensors.

Such temperature sensors may also be used before, during and afterpumping the fluid and therefore used to check the effectiveness of theapparatus.

Moreover, for certain embodiments, multiple longitudinally spacedcontainers are activated sequentially, and the array of temperaturesensors used to assess the resulting flow from communication paths.

Data may be recovered from the pressure sensor(s), before, during and/orafter the pump is operated in response to the control signal. Recoveringdata means getting it to the surface. Data may be recovered from thepressure sensor(s), before, during and/or after a perforating gun hasbeen activated in the well.

The data recovered may be real-time/current data and/or historical data.

Data may be recovered by a variety of methods. For example it may betransmitted wirelessly in real time or at a later time, optionally inresponse to an instruction to transmit. Or the data may retrieved by aprobe run into the well on wireline/coiled tubing or a tractor; theprobe can optionally couple with the memory device physically orwirelessly.

Memory

The apparatus especially the sensors, may comprise a memory device whichcan store data for recovery at a later time. The memory device may also,in certain circumstances, be retrieved and data recovered afterretrieval.

The memory device may be configured to store information for at leastone minute, optionally at least one hour, more optionally at least oneweek, preferably at least one month, more preferably at least one yearor more than five years.

The memory device may be part of sensor(s). Where separate, the memorydevice and sensors may be connected together by any suitable means,optionally wirelessly or physically coupled together by a wire.Inductive coupling is also an option. Short range wireless coupling maybe facilitated by EM communication in the VLF range.

Well/Reservoir Treatment

Manipulation of the well may be done by delivering chemical or acidtreatment to the well. The chemicals delivered may be a mixture ofdifferent substances.

For certain embodiments therefore, the container comprises a chemical orother fluid to be delivered, such as an acid, and “acid” treatments suchas “acid wash” or “acid injection” can be conducted. This may comprisehydrochloric acid or other acids or chemicals used for such so-calledacid treatments. The chemical/treatment fluid could be treatment ordelivery of the fluids to the well or the formation, such as scaleinhibitor, methanol/glycol; or delivering gelling or cutting agents forexample bromine trifluoride, breaker fluid, tracer or a chemical or acidtreatment.

The method may be used to clear or extend communication paths or clearthe well of any type of debris. This may improve well flow preferablyafter the isolation from the surface has been removed and/or be used toclear a portion of the well prior to or after perforating or at othertimes.

Communication path(s) can be perforations created in the well andsurrounding formation by a perforating gun. In some cases, use of aperforating gun to provide communication path(s) is not required. Forexample the well may be open hole and/or it may include a screen/gravelpacks, slotted sleeve or a slotted liner or has previously beenperforated. References to communication path(s) herein include all suchexamples where access to the formation is provided and is not limited toperforations created by perforating guns.

Acid wash normally treats the face of the wellbore, or may treat scalewithin a wellbore. Acids may be directed towards the specificcommunication paths that are damaged, for example by using openings in atube.

A conventional acid set-up and treatment conducted from surface is atime-consuming and therefore expensive process. Instead of aconventional acid treatment the method according to the invention may beperformed to try to mitigate debris. ‘Debris’ may include perforationdebris and/or formation damage such as filter cake.

The apparatus may be used to deliver chemicals such as tracers orbreaker fluids. Chemical barriers may also be deployed, or precursors toa chemical barrier for example cement type material. As an alternativeto cement, a solidifying cement substitute such as epoxies and resins,or a non-solidifying cement substitute may be used such as Sandaband™.References herein to cement include such cement substitutes.

An advantage of such embodiments is being able to deploy chemicals inparts of a well in which it may not be possible to deploy, or viablydeploy, using conventional means.

The method described herein may also be used to conduct a hydraulicfracturing or a minifrac operation.

In certain embodiments, the apparatus can be used to disrupt, inhibitand/or reverse the settling out and partial solidification of wellfluids in parts of the well, especially the annulus.

The apparatus is suitable for both openhole and perforated sections andcan be run with or without a perforation device.

Barrier Test

The apparatus may be provided below a barrier (such as certain annularsealing devices described herein) and the well manipulated such that apressure test carried out therebelow, when fluid is deployed. Theincreased pressure caused by fluid being pumped into this area, stressesthe barriers and so can be used to test the upper barrier. Indeed, itstresses it in the direction it is intended to withstand positivepressure, and so is a more effective direction of testing, compared withtesting it from above.

Thus, for some methods, there need not be communication between theformation and the well. For example a pressure test may be conducted ina closed area in the well, for example between barriers or annularsealing devices, i.e. there being no communication paths in the wellbetween the barriers or two annular sealing devices and the adjacentformation.

For example, a lower barrier bridge or cement plug is typicallyinstalled in a well to act as a primary barrier to the reservoir and isexposed, on its lower side, to reservoir pressure. Then a short distanceabove is a secondary barrier, often another bridge plug or cement plug.Such a secondary barrier can be tested from therebelow in accordancewith the procedures set out herein.

This compares to known methods of reducing the hydrostatic head abovesuch a barrier. This known test is time consuming and removes the safetybarrier of the hydrostatic head, compromising well control.

The apparatus may hang off the secondary barrier.

The secondary barrier can be set after the apparatus is deployed intothe well and charged.

One or more secondary containers, described herein above, may beprovided having an underbalance of pressure. This may be used to testthe secondary barrier from below, or to draw in, at least in part, thevolume of fluid added from the primary container after a test whichadded fluid has been completed.

Similarly, one or more secondary containers, described herein above, maybe provided having an overbalance of pressure. This may be used to testthe secondary barrier from below, or to replace, at least in part, thevolume of fluid removed from the section between the two barriers aftera test which removed fluid has been completed.

A discrete temperature array may be deployed in the section between thebarriers, or in a ring or helix above or below the barriers to assist inidentifying the location of any leak detected.

Charging Means

For certain embodiments including those used for such a barrier test,the apparatus may surprisingly have an in-situ charging means, eventhough for barrier tests, the pressure surrounding the apparatus isbeing increased by the pump pumping fluids into this area.

The charging means comprises a valve controlling a port. Preferredembodiments have a gas separated from the fluid by a floating piston.The valve is opened when pressure surrounding the apparatus is higherthan the pressure of the gas. It is therefore charged. The charged gasthen acts on the fluid to be deployed into the surrounding portion ofthe well to assist the pump to deploy the fluids.

The port may be used to deploy fluid and charge the gas. Alternatively,separate ports may be provided.

The charging means has some similar features to the pressure balancingmeans: the port may be a first port, and a second port may be providedin the apparatus between the container and a surrounding portion of thewell, the first and second ports separated within the apparatus by afloating piston.

Where separate ports are provided, the valve may be a one-way valve suchthat when open, it allows fluid communication from the well into thecontainer, but resists such communication from the container into thewell. In a closed position it resists communication in both directions.

For certain embodiments, the gas is compressed even more, by imposing apressure from or close to the surface of the well (before the barrier isset) so that the charging means allows for greater compression of thegas. The compressed gas is then sealed in by closing the valve, then atleast some of the additional pressure imposed from surface is removed,and the barrier to be tested is set. The gas acts on the fluid to bedeployed from the container into the well which facilitates the pump toexpel fluids into the surrounding portion of the well.

However, increasing the well pressure from the surface is not preferredor is limited for certain embodiments, for example where pressureactivated tools are present in the well.

Additionally or alternatively, gas in the apparatus may be pressurisedat the surface before it is launched, to similarly facilitate the pumpfor such an operation or for other applications within the scope of thepresent invention.

Deployment

An annular sealing device may or may not be present in the well.

For certain embodiments, the apparatus may be deployed with an annularsealing device or after an annular sealing device is provided in thewell following an earlier operation. In the former case, it may then beprovided on the same string as the annular sealing device and deployedinto the well therewith. In the latter case, it may be retro-fitted intothe well and optionally below the annular sealing device. In thisexample, it is normally connected to a plug or hanger, and the plug orhanger in turn connected directly or indirectly, for example bytubulars, to the annular sealing device. The plug may be a bridge plug,wireline lock, tubular/drill pipe set barrier, shut-in tool or retainersuch as a cement retainer. The plug may be a temporary or permanentplug.

Also, the apparatus may be provided in the well and then an annularsealing device deployed and set thereabove and then the method describedherein performed after the annular sealing device is run in.

The container may be sealed at the surface, and then deployed into thewell. ‘At surface’ in this context is typically outside of the wellalthough it could be sealed whilst in a shallow position in the well,such as up to 30 metres from the surface of the well, that is the top ofthe uppermost casing of the well. Thus the apparatus moves from thesurface and is positioned in the well with the container sealed, beforeoperating the pump. Depending on the particular embodiment and thedeployment method, it may be run in a well with no annular sealingdevice, or with the annular sealing device already thereabove or movepast a previously installed annular sealing device.

For certain embodiments, the entire apparatus may be below the annularsealing device, as opposed to a portion of the apparatus.

The first port of the apparatus may be provided within 100 m of acommunication path between the well and the reservoir, optionally 50 mor 30 m. If there is more than one communication path, then the closestcommunication path is used to determine the spacing from the first portof the apparatus. Optionally therefore, the first port in the containermay be spaced below communication paths in the well.

In certain embodiments, the apparatus may be run on a tubular string,such as a test, completion, suspension, abandonment, drill, tubing,casing or liner string. Alternatively, the apparatus may also beconveyed into the well on wireline or coiled tubing (or a tractor). Theapparatus may be an integral part of the string.

The apparatus is typically connected to a tubular before it is operated.Therefore whilst it may be run in by a variety of means, such aswireline or tubing, it is typically connected to a tubular such asproduction tubing or casing when in the well, before it is operated.This provides flexibility for various operations on the well.

The connection may be by any suitable means, such as by being threaded,gripped, latched etc. onto the tubular. Thus normally the connectionbetween the tubular takes some of the weight of the apparatus, albeitthis would not necessarily happen in horizontal wells.

The apparatus may be provided towards or at the lowermost end of alowermost casing or liner. The container may be defined, at least inpart, by the casing or liner. Therefore the lowermost part of thecontainer may be within 100 m of the bottom of the well and indeed maybe the bottom of the casing.

The string may be deployed as part of any suitable well operation,including drilling, well testing, shoot and pull, completion, work-over,suspension and/or abandonment operation.

The string may include perforating guns, particularly tubing conveyedperforating guns. The guns may be wirelessly activatable such as fromthe wireless signals.

In such a scenario, there may not be straightforward access below gunsto the lower zone(s). Thus when run with such a string, embodiments ofthe invention provide means to pump fluids into such a zone.

A plurality of apparatus described herein may be run on the same string.For example spaced apart and positioned within a section or isolatedsections. Thus, the apparatus may be run in a well with multipleisolated sections adjacent different zones. When the port of theapparatus is isolated from the surface of the well, flow may continuefrom a separate zone of the well, which is not in pressure communicationwith the port, and not isolated from the surface of the well.

The apparatus may be dropped off an associated carrying string after thepump has been operated or for any other reason (for example it is notrequired and is not possible or useful to return it to surface). Thus itis not always necessary to return it to the surface.

A variety of arrangements of the apparatus in the well may be adopted.The apparatus may be positioned substantially in the centre of the well.Alternatively the apparatus may be configured as an annular tool toallow well flow through the inner tubular, normally before the well isisolated, after the isolation is removed, or from another section.Therefore, the container is formed in an annular space between two tubesand the well can flow through the inner tube.

In other embodiments, the apparatus can be offset within the well, forexample attached/clamped onto the outside of a pipe or mounted offsetwithin a pipe. Thus it can be configured so apparatus or other objects(or fluid flow) can move through the bore of the pipe without beingimpeded. For example it may have a diameter of 1¾ inches offset inside a4″ inner diameter outer pipe. In this way, one or more wirelineapparatus can still run past it, as can fluid flow.

Other apparatus may not provide an arrangement to allow flow past—forexample, the container may take up the whole cross-section of thetubing. In one embodiment, below an annular sealing device and beneathcommunication paths, flow is directed through an annulus between tubingand casing. This may be above or below perforating guns where flow isalready normally directed through the tubing/casing annulus.

For certain embodiments, the apparatus may be deployed in a central boreof a pre-existing tubular in the well, rather than into a pre-existingannulus in the well. An annulus may be defined between the apparatus andthe pre-existing tubular in the well.

The apparatus may be run into the well as a permanent apparatus designedto be left in the well, or run into the well as a retrievable apparatuswhich is designed to be removed from the well.

Short Interval

The method to manipulate the well according to the earlier aspects orthe third aspect (detailed below) of the invention, may include themethod of conducting a short interval test and so the first port may beisolated in a short interval. The pump member can be activated inresponse to the control signal normally to pump fluid from (or possiblyinto) the short interval thereby manipulating the well.

In contrast to the earlier embodiments where the first port of theapparatus is provided between two barriers and pressure tests conducted,the short interval is normally in communication with the reservoirthrough at least one communication path.

According to a third aspect of the present invention there is provided amethod to manipulate a well by conducting a short interval test,comprising:

-   -   providing a pressure sensor in the well;    -   providing an apparatus in the well, the apparatus comprising a        container having a volume of at least 5 litres and a port to        allow fluid and optionally pressure communication between a        portion of an inside of the container and an outside of the        container;    -   the port of the apparatus being below a first portion of a        packer element and above a second portion of a or the packer        element, said portions spaced apart from each other by up to 10        m thus defining a short interval, and each engaging with an        inner face of casing or wellbore in the well, and being at least        100 m below a surface of the well;    -   the short interval including at least one communication path        between the well and the formation;    -   the apparatus further comprising:        -   a pump adapted to move fluid from the surrounding portion of            the well into at least a portion of the container via the            port;        -   a control mechanism comprising a communication device            configured to receive a control signal for moving the valve            member;    -   deploying the apparatus into the well on a tubular,    -   sending a control signal from outwith the short interval to the        control mechanism at least in part by a wireless control signal        transmitted in at least one of the following forms:        electromagnetic, acoustic, inductively coupled tubulars and        coded pressure pulsing;    -   operating the pump in response to said control signal to allow        fluid to enter the container; and,    -   drawing in at least 5 litres of fluid into the container from        the well.

In alternative embodiments, pressure in the container may be reducedcompared to an outside of the container, such as the surrounding portionof the well, and rather than a pump, a valve can be used to control thereduced pressure in order to draw fluids into the container. Furtherembodiments have both options.

The short interval may be defined by one packer element shaped to seal a(relatively small) interval formed from a recess within, or the shapeof, the overall packer element. Thus for such embodiments, said firstand second portions of a packer element belong to the same packerelement. A first packer may therefore include the first and secondportions of the packer element, for example a single circular packerelement.

In other embodiments, the short interval is defined between packerelements such as the packer element described more generally hereinabove and a further packer element. For such embodiments said first andsecond portions of packer elements are separate packer elements. Forsuch embodiments, a first packer may therefore include the first portionof the packer element, and a second packer may include said secondportion, which is a different packer element.

Thus there can be a second packer element where at least the port of theapparatus is positioned above the second packer element. The entireapparatus may be positioned above said second packer element. The secondpacker element may be wirelessly controlled. Thus it may be expandableand/or retractable in response to wireless signals.

Thus in contrast with the first aspect of the invention, the port of theapparatus in the third aspect is below the first packer element (a formof annular sealing device) whereas in the first aspect of the inventionthe apparatus is below the annular sealing device.

The short interval, i.e. the distance between two annular sealingdevices, may be less than 10 m, optionally less than 5 m or less than 2m, less than 1 m, or less than 0.5 m. These distances are taken from thelowermost point of the first packer element, and the uppermost point ofthe second packer element. Thus this can limit the volume and so theapparatus is more effective when the first port is exposed to thelimited volume.

The wireless signal may be sent from outwith the short interval to thecontrol mechanism entirely in its said wireless form.

Inflatable packers may comprise said packer elements especially foropenhole applications. For such openhole applications, the packerelements used in the short interval test may be relatively long, that is1-10 m, optionally 3-8 m. This is because the pressure drop in theformation may cause flow around the packer element. Increasing thelength of the packer element reduces the risk of this occurring.

In preferred embodiments, fluid to/from the container is pumpedgradually over several seconds (such as 5-10 seconds), or longer (suchas 2 minutes-6 hours) or even very slow (such as 1-7 days).

For certain embodiments, such a test can provide an initial indicationon the reservoir response to an injection/hydraulic fracturingoperation, and may reduce the requirement to conduct a larger scaleinjection/hydraulic fracturing test.

Sensors optionally record the pressure especially of the formation forexample at the port or outside the apparatus.

One or both of the packer element(s) may be part of an annular sealingdevice, described more generally herein.

The packer(s) may be resettable, so that it/they may be set in a firstposition and a first test may be performed, then disengaged, moved andreset in a different position, where a second test may be performed.Such a procedure is especially suitable in an openhole section of thewell.

The packer(s) used in a short interval manipulation may also be deployedas part of a drill stem test (DST) string. For example, when performinga drill stem test, a short interval test may be conducted in a sectionof the well above or below the section being tested in the DST.

Where space permits, a perforating device such as a perforating gun maybe provided in the short interval. This short interval manipulation isalso particularly suitable to being performed in an openhole section.

In order to conduct a short interval test, at least one packer ispreferably deployed on a tubular, such as drill pipe, casing andoptionally coiled tubing.

The apparatus may be part of a string which includes a drill bit. Thepacker(s) may be mounted on said string, and activated to engage with anouter well casing or wellbore.

There may be a connector, as described herein more generally, connectingthe apparatus to the first packer, the connector optionally being abovethe apparatus and below the first packer element.

The outside of the container according to the third aspect of theinvention is a surrounding portion of the well between the first andsecond portions of the packer element(s).

The method described herein may be used to conduct an intervalinjectivity, permeability, pressure, hydraulic fracturing, minifrac orsimilar test/manipulation.

In one embodiment, the well may be manipulated by conducting a flowtest. Flow from the reservoir is produced into the short interval, andproceeds through the apparatus. The resulting pump rate can be used tocontrol and/or estimate the flow rate from the reservoir.

Optional features described above with respect to the first and secondaspects of the invention are optional features with respect to the thirdaspect of the invention. For example, a floating piston and dump chamberare especially useful in embodiments in accordance with the third aspectof the invention. For example the container having volumes of at least50 litres (l), optionally at least 100 l and optionally a volume of atmost 3000 l, normally at most 1500 l, optionally at most 500 l.

Further Procedure

The method to manipulate the well, may be a method to clear the wellespecially by delivering fluids such as chemicals, optionally inpreparation for a test or further procedure.

According to a further aspect of the present invention there is provideda method to conduct a procedure or test on a well, comprising:

-   -   conducting the method to manipulate the well or formation, as        described herein;    -   conducting a procedure/test on the well, the procedure/test        includes one or more of a build-up test, drawdown test,        connectivity tests such as an interference test or pulse test, a        drill stem test (DST), extended well test (EWT), hydraulic        fracturing, mini frac, pressure test, flow test, well/reservoir        treatment such as an acid treatment, permeability test,        injection procedure, gravel pack operation, perforation        operation, image capture, string deployment, workover,        suspension and abandonment.

The test is normally conducted on the well before removing the apparatusfrom the well, if it is removed from the well.

Embodiments of said further aspect may improve the pressure or fluidcommunication across the face of the formation and improve theperformance of the tests/procedures. Thus the method of the inventioncan improve the reliability and/or quality of data received fromsubsequent testing or improve other procedures.

The method to conduct a test/procedure on the well may also includeperforating the well. However, the method of the present invention maybe independent from operation of the guns. The well may be openholeand/or pre-perforated.

The apparatus may be used to clear the surrounding area, for example byexpelling a clear fluid, before images are captured.

The procedure may be a drill stem test (DST). Thus a DST string and theannular sealing device are deployed as part of the DST. After the finalDST flow period or build up has been conducted, a valve controlling flowinto the DST test string is closed. The valve is normally below theannular sealing device though for certain embodiments it may bethereabove. The valve may be controlled by said control signals. Theportion of the DST string above the valve (often above the annularsealing device) can then, optionally, be removed. The well below theannular sealing device can then be monitored as described herein.Notably the underbalanced container may be activated when required, suchas at a much later date. Moreover, communication paths below the annularsealing device between the well and the reservoir need not have beencontaminated by kill fluid, and so better connectivity with reservoircan be maintained, providing more useful data when conducting suchconnectivity tests. If the well is abandoned by cementing above theannular sealing barrier (and normally adding a further barrier) thewireless signals may still be used to monitor the well below the annularsealing device. Data recovery before, during or after the apparatusbeing activated is normally achieved through wireless signals.

A pulse test is a type of connectivity test where a pressure pulse issent from one well/isolate section to another, and the relatively subtlepressure wave detected in the second well. It can then be inferredwhether and to what extent the reservoir (or a particular zone) is openand allows pressure communication between these wells/isolated sections.This can be useful to determine the optimum strategy for extractingfluids from the reservoir.

Another connectivity test is an interference test which monitors longerterm affects at an observation well following production (or injection)in a separate well, and useful data can also be obtained regarding thereservoir between the wells or isolated sections, such as connectivity,permeability, and storage capacity.

For such connectivity tests, the well being manipulated according toembodiments of the present invention is the observing well/sections.Thus the method described herein may include observing for pressurechanges in the well/section as part of a connectivity test.

For certain other embodiments however, the method of manipulating thewell may be the well—particularly the isolated section—from where pulsesare sent using the apparatus. For example, in a multi-lateral well, theapparatus may send a pressure pulse from one side-track of the same wellto another. Side tracks (or the main bore) of wells which are isolatedfrom each other are defined herein as isolated sections.

Miscellaneous

The well may be a subsea well. Wireless communications can beparticularly useful in subsea wells because running cables in subseawells is more difficult compared to land wells. The well may be adeviated or horizontal well, and embodiments of the present inventioncan be particularly suitable for such wells since they can avoid runningwireline, cables or coiled tubing which may be difficult or not possiblefor such wells.

References herein to perforating guns includes perforating punches anddrills, which are used to create a flowpath between the formation andthe well.

The surrounding portion of the well, is the portion of the wellsurrounding the apparatus immediately before the pump is activated inresponse to the control signal. More precisely it is the pressure of thefluid at or ‘surrounding’ the first port.

The volume of the container is its fluid capacity.

Transceivers, which have transmitting functionality and receivingfunctionality, may be used in place of the transmitters and receiversdescribed herein.

Unless indicated otherwise, any references herein to “blocked” or“unblocked” includes partially blocked and partially unblocked.

All pressures herein are absolute pressures unless stated otherwise.

The well is often an at least partially vertical well. Nevertheless, itcan be a deviated or horizontal well. References such as “above” andbelow” when applied to deviated or horizontal wells should be construedas their equivalent in wells with some vertical orientation. Forexample, “above” is closer to the surface of the well through the well.

A zone is defined herein as formation adjacent to or below the lowermostbarrier or annular sealing device, or a portion of the formationadjacent to the well which is isolated in part between barriers orannular sealing devices and which has, or will have, at least onecommunication path (for example perforation) between the well and thesurrounding formation, between the barriers or annular sealing devices.Thus each additional barrier or annular sealing device set in the welldefines a separate zone except areas between two barriers or annularsealing devices (for example a double barrier) where there is nocommunication path to the surrounding formation and none are intended tobe formed.

“Kill fluid” is any fluid, sometimes referred to as “kill weight fluid”,which is used to provide a hydrostatic head typically sufficient toovercome reservoir pressure.

Embodiments of the present invention will now be described, by way ofexample only, with reference to the accompanying figures in which:

FIG. 1 is a schematic view of a first apparatus which may be used in themethod of the present invention;

FIG. 2 is a schematic view of a second apparatus including a floatingpiston in accordance with the present invention;

FIG. 3 is a schematic view of a well with multiple zones, illustratingmethods in accordance with the present invention;

FIG. 4 is a schematic view of a well illustrating further methods inaccordance with the present invention;

FIG. 5 is a schematic view of a further apparatus including a floatingpiston and a control container in accordance with the present invention;

FIG. 6a is a schematic view illustrating the FIG. 5 apparatus used in ashort interval test in accordance with the present invention;

FIG. 6b is a schematic view of the apparatus used in a further shortinterval test in an uncased section of a well;

FIG. 7 is a schematic view of a further embodiment of the apparatusincluding a charging means in accordance with the present invention;

FIG. 8 is an alternative apparatus having a charging means in accordancewith the present invention; and,

FIG. 9 is an alternative apparatus where a well casing defines part ofthe container.

FIG. 1 shows an apparatus 60 in accordance with the present invention inthe form of a modified pipe, comprising a container 68, a side opening61, an electrically powered pump 62 in the opening 61, a controlmechanism comprising a pump controller 66 and wireless transceiver 64,and a battery 63.

The pump 62 is configured to pump fluids from/to the container 68to/from a surrounding portion of the well (outside the apparatus 60)thus selectively allowing fluid communication between a portion of thecontainer 68 and the surrounding portion of the well.

The pump 62 is controlled by the pump controller 66. The transceiver 64is coupled to the pump controller 66 and is configured to receive awireless control signal.

The components of the control mechanism (the transceiver 64 and the pumpcontroller 66 which controls the pump 62) are normally provided adjacenteach other, or close together as shown; but may be spaced apart.

In the illustrated embodiment, the container 68 comprises liquid 90 tobe deployed into the well, and a gas 92, such as nitrogen thereabove. Insuch embodiments, a wireless signal is received by the transceiver 64instructing the pump 62 to operate and pump the fluid 90 from thecontainer 68 into the surrounding portion of the well. The gas 92expands as the liquid 90 is directed into the well.

In some embodiments, the apparatus 60 can be used for tracer discharge.

FIG. 2 shows an embodiment of an apparatus 160. Like parts with the FIG.1 embodiment are not described in detail but are prefixed with a ‘1’.The apparatus 160 comprises a chamber 168 with a floating piston 174, adynamic seal 175 between the floating piston 174 and the container'sinner bore and a check valve 177 and a pump 162 both provided in anopening 161 to the container 168. Significantly, a pressure balancingport 173 is also provided between the container 168 and the surroundingportion of the well, on the opposite side of the floating piston 174from the opening 161. A battery 163, transceiver 164 and pump controller166 are also provided.

The check valve 177, when in an open position, resists fluid flow fromthe well into the container 168 but allows fluid flow from the containerinto the well. The pump 162 is controlled by the pump controller 166. Acommunication device in the form of a transceiver 164 is coupled to thepump controller 166 and is configured to receive a wireless controlsignal, such as from an operator at the surface of the well.

In the present embodiment, the pressure balancing port 173 allows thepump 162 to have a lower rating as it only needs to overcome arelatively small pressure difference to move the fluid between thecontainer 168 and the well; not a larger pressure difference forembodiments without such a port, which also need to overcome thedifference in pressure between the container 168 and the well.

In use, the portion of the container 168 above the floating piston 174is filled with liquid to be deployed. The sequence begins with the checkvalve 177 in a closed position and the pump 162 switched off. Anoperator at the surface of the well sends a wireless signal to thetransceiver 164 coupled to the pump controller 166 which instructs thepump 162 to turn on and the check valve 177 consequently opens. The pump162 then begins moving the liquid from the container 168 above thefloating piston 174 into the surrounding portion of the well. As thefluid is expelled from the container 168, fluid from the well enters thechamber 171 via the pressure balancing port 173.

The rate at which the liquid in the container 168 above the floatingpiston 174 is expelled into the surrounding portion of the well iscontrolled by the speed at which the pump 162 operates.

In other embodiments, the check valve allows fluid flow from the wellinto the container but resists fluid flow from the container into thewell. In such embodiments, the pump directs fluid from the surroundingportion of the well into the container for example, to conduct an inflowtest. In such embodiments, the inlet port and pressure balancing portare normally open onto portions of the well isolated from each other.

In an alternative FIG. 2 embodiment there is no pressure balancing port.However the floating piston is present which seals a gas containingsection, from a fluid/liquid containing section which is between theport and the floating piston.

FIG. 3 shows a multi-zone well 114 comprising a liner hanger 129 andliners 112 a and 112 b, and two sets of apparatus 260 and 60.

The apparatus 60 has been previously described. It may be orientated inuse as drawn in FIG. 1, or as shown in FIGS. 3 and 4 with a pipe (notshown) within the container 68 provided to draw liquid from a bottom ofthe container 68 to the opening 61 when the pump 62 operates.

The apparatus 260 is similar to apparatus 60, 160 and can have theconfiguration described for apparatus 60 in FIG. 1 or apparatus 160 ofFIG. 2. Like parts with earlier embodiments are not described in detailbut are prefixed with a ‘2’.

Additionally, apparatus 260 also comprises an outlet tube 135, which hasmultiple openings or outlets 137 through which fluid can be releasedonto an adjacent upper slotted liner 154 a.

The well 114 has its own well apparatus 110 which comprises two packerelements 122 a & 122 b which splits the well into a plurality ofisolated sections. A first, upper, section comprises the upper packerelement 122 a, a wirelessly controlled upper sleeve valve 134 a, theupper apparatus 260 and the upper slotted liner 154 a. The sleeve valve134 a, together with the packer 122 a are the isolating components whichisolate the port of the apparatus 60 a′ from the surface of the well.

A second, lower, section comprises the lower packer element 122 b, awirelessly controlled lower sleeve valve 134 b, the lower apparatus 60and a lower slotted liner 154 b. For this second section, the sleevevalve 134 b, together with the packer 122 b are the isolating componentswhich isolate the port of the apparatus 60 a″ from the surface of thewell. Moreover, they also function as lower isolating components for thefirst upper section.

The slotted liners 154 a, 154 b create communication paths between theinside of the liner 112 a and the adjacent formation.

Isolating the sections from each other provides useful functionality formanipulating each adjacent zone individually though this is not anessential feature of the invention. For example, the valve 134 a in theupper section can be closed to isolate the upper apparatus 60 a′ fromsurface of the well, whilst flow continues from the zone adjacent thesecond lower section.

The well 114 further comprises a packer such as a swell packer 128between an outer surface of the liner 112 a and a surrounding portion ofthe formation. The upper tubular 118 and lower tubular 116 arecontinuous and connected via the upper packer element 122 a and thelower packer element 122 b. Portions of the upper tubular 118 and lowertubular 116 thus serve as connectors to connect the upper apparatus 260and lower apparatus 60 to the packer elements 122 a, 122 b respectively.

Instrument carriers 140, 141 and 146 are provided in each section andalso above the packer element 122 a. Each instrument carrier comprises apressure sensor 142, 143, and 148 respectively, and a wireless relay144, 145, and 149 respectively.

In use, fluid flows through the lower slotted liner 154 b and into thelower tubular 116 via the lower sleeve valve 134 b. The flow continuesthrough the lower tubular 116 past the lower packer element 122 b, theupper apparatus 260 and instrument carrier 146 before continuing throughthe upper tubular 118 towards the surface. The upper apparatus 260 (incontrast to the lower apparatus 60) does not take up the full bore ofthe upper tubular 118 and so fluid can flow therepast from below withoutbeing diverted outside of the upper tubular 118.

From an upper zone, the well flows through the slotted liner 154 a andinto the upper tubular 118 via the sleeve valve 134 a. The flowcontinues through the upper tubular 118, past the upper packer element122 a towards the surface.

The flow may be from the upper zone adjacent the well 114 only, thelower zone adjacent the well 114 only, or may be co-mingled, that isproduced from the two zones simultaneously. For example, fluids from theslotted liner 154 b combine with further fluids entering the well 114via the upper slotted liner 154 a to form a co-mingled flow.

The apparatus 260 functions as described for earlier embodiments of theapparatus save that it distributes liquid onto the upper slotted liner154 a. It is activated when the outlets 137 are isolated from thesurface of the well such as prior to flowing the well, or after flowingthe well. A wireless signal is sent from a controller (not shown) to apump controller via a transceiver and a pump operates to expel fluidfrom the container to the surrounding portion of the well (or viceversa). The apparatus 260 is particularly suited to deploying acid foran acid treatment, as it can distribute the fluid over the slotted liner154 a via the tube 135. Optionally pressure in the well can be increasedby conventional means to “inject” the acid into the formation.

The apparatus 60 is activated as previously described.

Thus embodiments of the apparatus are particularly suited to deliveringfluids into the well in a controlled manner such as tracers. Radioactiveor chemical tracers may be added and detected elsewhere in the well orat surface, for example to gain more information on fluids produced fromseparate zones, when co-mingled flow is occurring.

FIG. 4 illustrates a method of the present invention used during a drillstem test (DST) operation. Two apparatus 60 and 260 are provided in twodifferent sections of a well 214, the sections separated by an annularsealing device in the form of a packer element 222.

The apparatus 60 is provided above the packer element 222. Above thepacker element 222, the well 214 includes a tubing 218 and a casing 212,with an annulus 291 therebetween. A tester valve 230 and a circulationvalve 231 are also provided. In use, the annulus 291 between the tubing218 and the casing 212 above the packer element 222 includes well fluidswhich may be relatively dense fluid or mud, especially for high pressurewells. The present inventors have noted that under certaincircumstances, the mud may become particularly dense and indeedpartially solidify, close to the packer element 222, for example as theheavier components settle due to gravity or other forces. Thetransmission of pressure signals close to or through this substance ismore difficult—signals may only be received intermittently or not atall. For example, transmission of signals to a tester 230 or circulation231 valve can be inhibited.

The apparatus 60 therefore functions to pump fluid out of the container68 to disrupt, inhibit and/or reverse the settling out and partialsolidification of well fluids in the annulus. Signals to the testervalve 230 or circulation valve 231 above the apparatus 60 are thereaftermore reliable.

A variety of alternatives can be provided. The pump may be operatedintermittently so that the disruption can be repeated at spaced aparttimes. Further containers or indeed apparatus may also be used for thesame purpose.

The apparatus 260 is provided below a perforating gun 250. Two outlettubes 135, 136 extend from opening 261 a of the apparatus 260 over theperforating gun 250. The tubes 135, 136 can have multiple outlets 137 asshown, or alternatively a single outlet, for example to deploy a tracer.Each tube 135, 136 has a valve 265 a which can be independentlycontrolled to direct fluid from the container 268 a onto selectivelydifferent portions of the perforation interval 252. Both tubes 135, 136are controlled by the same pump 262 a. Further valves may be added toprovide independent control to each opening. The tubing 218 andperforating gun 250 serve as a connector to connect the apparatus 260 tothe annular sealing device 222.

A discrete temperature array 253 is provided adjacent to theperforations 252 and connected to a controller 255. In this embodimentthe discrete temperature array has multiple discrete temperature sensorsalong the length of a small diameter tube.

After isolation from the surface of the well, the apparatus 260 isactivated wirelessly causing the pump 262 a to start, which can directfluid, such as acid or tracer, onto the perforations.

The two apparatus 60, 260 illustrated in FIGS. 3 and 4 can be usedindependently of each other in single or multiple zone wells and areillustrated in the same figure and same well for brevity.

A further embodiment 360 of apparatus suitable for use in the method ofthe invention is shown in FIG. 5. Like parts with earlier embodimentsare not described in detail but are prefixed with a ‘3’.

The apparatus 360 comprises a container 368 having a floating piston 374with seals 375 and a pump 362. A valve 377 (optionally a check valve) isprovided in an opening 361 of the container 368.

The apparatus 360 also comprises other components which are not shown,including a battery, a pump controller and a transceiver for wirelesssignals.

In contrast to the FIG. 2 embodiment, the pump 362 is provided in acentral portion, between the container 368 and a control container 380.The control container 380 has a second floating piston 382, along withseals 383; and below the second floating piston 382 a port 373 isprovided to allow a pressure balance between the control container belowthe second floating piston 382 and the surrounding portion of the well.

A control fluid is provided above the second floating piston 382 whilsta fluid to be expelled is provided in the container 368 above thefloating piston 374. In use, a wireless signal is sent to the pump 362via the transceiver and pump controller, and the pump 362 pumps controlfluid from the control container 380 into the container 368, below thefloating piston 374. This in turn moves the floating piston 374 andexpels the fluid in the container 368 to the surrounding portion of thewell.

The pump 362 can also operate in a reverse direction to that described.The control fluid is pumped from the container 368 below the floatingpiston 374 into the control container 380 thus drawing well fluids intothe container 368 above the floating piston 374.

The apparatus 360 can be cycled between expelling and drawing in fluidsindefinitely. An advantage of such an apparatus is that the pump pumps a‘clean’ control fluid rather than the well fluids which are much morevariable in their physical properties which may affect the flow rate andany related data.

In alternative embodiments, rather than a port 373 allowing pressurebalance, the section below the second floating piston may be sealed andpre-charged with gas under pressure.

FIG. 6a shows one application of the FIG. 5 apparatus for use with ashort interval test using the apparatus 360. The packers 322 a and 322 bare set in the casing 312, and a perforating tool 350 receives awireless signal to activate and punch a hole 352 in the casing 312 andadjacent formation 351.

The apparatus 360 then receives a control signal to start the pump 362to pump control fluid from the control container 380 into the container368 below the piston 374, which in turn expels fluids in the container368 above the piston 374. In this way, an injection test can be carriedout, during which the build-up of pressure can be monitored usingpressure sensor(s). Data from the pressure sensor(s) can be transmittedwirelessly, for example by acoustic or electromagnetic signals, to thesurface to monitor the results of the test.

Optionally a tube with multiple exits can be provided at the opening 361to distribute fluids over an area, such as a plurality of communicationpaths.

Optionally the pump 362 can be reversed to draw in fluids from the well.Moreover, a variety of alternatives are available for such a procedure.In one embodiment, the pump 362 can be stopped and started before thecontainer 368 has expelled its contents (or if operating in reverse,before it has been filled with well fluid) and this start/stop sequencecan be repeated. In one embodiment, an operator can unseat the packers322 a, 322 b, reposition the apparatus 360, re-seat the packers 322 a,322 b, and then conduct the procedure again.

In one alternative embodiment, a second container is provided at adifferent pressure to the surrounding portion of the well, for exampleit may be underbalanced. This may be activated to, for example, purgethe surrounding area of debris before the apparatus 360 is operated.Such a further container having a different pressure, may be combinedwith other embodiments described herein.

FIG. 6b shows a similar short interval test using a well apparatus 310b, apparatus 360 b in an uncased/openhole section of well 315.

In this embodiment a single packer 322 c is provided with an opening 394aligned with a port 361 b of the apparatus and so a portion of thepacker is above the port 361 b and a portion of the packer is below theport 361 b, thus isolating a short interval. The apparatus 360 b alsocomprises a pump 362 b and a valve 377 b in close proximity to eachother. A pressure gauge 395 b monitors the pressure of the interval andis powered by a battery 363 b.

The short interval test or other manipulation can be conducted followingthe same procedure described with respect to FIG. 6 a.

In certain situations, it may be useful to control the interval forinstance to add ‘kill’ fluid. Optionally therefore, a sleeve valve 330can be provided between the tubing string 318 and surrounding annulus291A which can be opened to allow pressure connectivity between theinterval and the string above, for example to allow kill fluid to enterthe interval.

Certain embodiments of the invention may be used to conduct a barriertest in a well. They are placed beneath the sealed barrier, and thenexpel fluids in order to increase the volume below the barrier and sostress the barrier in order to test it.

FIG. 7 shows apparatus 460 a with a charging means in accordance withthe present invention and which is particularly suited to such barriertests. Like parts with earlier embodiments are not described in detailbut are prefixed with a ‘4’.

The apparatus 460 a, comprises a container 468 a, a pump 462 a in a port461 a and a side port 473 a with a valve 477 a. The container has afloating piston 474 a separating a first liquid containing section 491 afrom a second gas containing section 492 a.

In use, the apparatus 460 a may be deployed with the floating piston 474a positioned such that around three quarters of the container 468 a isthe gas containing section 492 a and around one quarter is the liquidcontaining section 491 a. As the apparatus is moved deeper into thewell, the increased well pressure, will cause movement of the floatingpiston 474 a and compression of the gas.

The apparatus is positioned below the barrier to be tested, with thevalve 477 a open and well fluids are received into the first section 491a of the container 468 a compressing or ‘charging’ the gas in the secondsection 492 a to the surrounding well pressure. The valve 477 a is thenclosed.

When the barrier (not shown) is in place, the pump 462 a is operated topump the fluid from the first section 491 a of the container 468 a intothe surrounding portion of the well. The compressed gas in the secondsection 492 a of the apparatus 460 a acts on the liquid in the firstsection 491 a so that it is substantially at well pressure before thefurther action of the pump 462 a, thus facilitating the pump 462 a tooperate (compared to pumping a liquid having an atmospheric pressure).In this way, a lower pump rating may be used.

The barrier can be formed before or after the apparatus is charged.

For certain embodiments, the pressure may be stored as described whenthe well pressure is increased from the surface, which will furthercharge the apparatus. This may be done by applying pressure or beforecirculating heavy fluids in the well's hydrostatic head for lighterfluids. It may take advantage of the well pressure changing for someother reason/operation or be done intentionally to increase the chargeto the apparatus. In such circumstances, the charging would normallytake place before the barrier is set.

FIG. 8 shows an apparatus 460 b which is a modified version of theapparatus 460 a where the charging means facilitates deploying aspecific fluid in the well (for example acid). Like parts will not bedescribed again in detail but will be suffixed with a ‘b’ rather than an‘a’.

In common with the FIG. 7 embodiment, the FIG. 8 apparatus 460 bcomprises a pump 462 b in a port 461 b, a floating piston 474 b within acontainer 468 b, a first liquid containing section 491 b and a secondgas containing section 492 b.

In contrast to the FIG. 7 embodiment, a valve 477 b in the apparatus 460b is provided in a second port 473 b at an opposite end to the pump 462b. Moreover a second floating piston 482 b is provided in the container468 b between the second port 473 b and the first floating piston 474 b,to define a third ‘charging’ section 493 b of the container 468 b.

The apparatus 460 b can be similarly charged via the second port 473 band the apparatus 460 b operated in the same manner as that describedabove with respect to apparatus 460 a. A benefit of the FIG. 8 apparatusover the FIG. 7 apparatus is that the liquid expelled from the liquidcontaining section 491 b can be chosen for an alternative (oradditional) purpose than pressure testing, for example acid treatment,rather than using liquid from the well.

In FIG. 9 an alternative embodiment of an apparatus 560 with a container568 is illustrated. Common features, for example pump 565 and valve 562,with earlier embodiments are not described again in detail for brevitybut use the same latter two digits as reference numerals with a ‘5’prefix. In contrast to earlier figures the container 568 is in partdefined by the surrounding casing 512 and outlet tube 535 with openings537 is secured to a portion of the casing 512 above the container 568 byclamps 596. Such an apparatus 560 is normally run on the casing 512 whencompleting the well. An advantage of such an embodiment is that thecontainer can have larger volumes without running further tubing intothe well. The apparatus 560 may have flow bypass 597 for cementingduring completion or for circulating during deployment. Such embodimentsare useful for deploying treatments to a toe of a deviated well.

It will be appreciated that the method according to the invention can becarried out using a variety of apparatus 60, 160, 260, 360, 360 b, 460a, 460 b, 560 and the examples using these different apparatus indifferent contexts are not limiting, and the different apparatus can beused in the different positions shown in the FIGS. 3, 4, 6 a, 6 b and 9wells.

Modifications and improvements can be incorporated herein withoutdeparting from the scope of the invention. For example variousarrangements of the container and electronics may be used, such aselectronics provided in the apparatus below the container.

That claimed is:
 1. A method to manipulate a well, comprising: providingan apparatus in the well below an annular sealing device the annularsealing device engageing with one of an inner face of casing and awellbore in the well, and being at least 100 m below a surface of thewell; and wherein a connector is provided connecting the apparatus tothe annular sealing device, the connector being above the apparatus andbelow the annular sealing device; the apparatus comprising: a containerhaving a volume of at least 1 litre (l); a port to allow fluidcommunication between a portion of the container and a surroundingportion of the well; an electrically powered pump configured to directfluids to/from the container from/to the surrounding portion of thewell; a battery to supply electrical power to the pump; a controlmechanism to control the pump, and comprising a communication deviceconfigured to receive a control signal for operating the pump; runningthe apparatus into the well; then, isolating the port of the apparatusfrom a surface of the well; sending a control signal to thecommunication device at least in part by a wireless control signaltransmitted in at least one of the following forms: electromagnetic andacoustic; operating the pump in response to said control signal andpumping fluid from within the container to the surrounding portion ofthe well; and wherein at least one pressure sensor is provided in thewell below the annular sealing device, the at least one pressure sensorcoupled to a wireless transmitter; and wherein data is transmitted fromthe transmitter to above the annular sealing device.
 2. A method asclaimed in claim 1, wherein the apparatus is connected to a tubularbefore the pump is operated.
 3. (canceled)
 4. A method as claimed inclaim 1, wherein the electrical pump is a positive displacement pump,optionally a reciprocating piston pump which is reciprocated at leastfive times.
 5. A method as claimed in claim 1, wherein the fluid pumpedinto the surrounding portion of the well includes at least 1 l of fluidadded to the apparatus before it was run into the well.
 6. A method asclaimed in claim 1, wherein the fluid is one of an acid, breaker fluid,tracer, gelling chemical and inhibitor.
 7. A method as claimed in claim1, including using the apparatus to conduct at least one of an intervalinjectivity test, permeability test, pressure test, hydraulic fracturingtest, a barrier test, a chemical delivery operation, and well/reservoirtreatment such as an acid treatment.
 8. A method as claimed in claim 7,wherein the apparatus is used to conduct a pressure test, the pressuretest being conducted on a barrier by the apparatus being provided belowthe barrier, the pump being operated causing fluid to be released fromthe container to increase pressure below the barrier, and the pressurebelow the barrier is then monitored.
 9. A method as claimed in claim 8,further comprising a charging system having a valve on at least one ofthe and another port, the method including providing gas in thecontainer, exposing the gas to well pressure via said port to compressthe gas, closing said port with said valve to resist fluid and pressurecommunication from the well into the container, using the compressed gasto facilitate the pump to release fluid from the container into thewell, and; wherein optionally before the barrier is set, the well ispressurised from surface to further increase the pressure in the welland further compress the gas in the container, the valve at the portbeing closed before the pressure from the surface is reduced. 10.-13.(canceled)
 14. A method as claimed in claim 1, wherein the container hasat least one of a floating piston and bladder separating a first and asecond section in the container and sealing them from each other withinthe container, the first section being in fluid communication with theport. 15.-28. (canceled)
 29. A method as claimed in claim 1, wherein theport of the apparatus is provided above a second annular sealing device.30. A method as claimed in claim 29, including conducting a shortinterval test wherein the packer element of the annular sealing deviceand a packer element of the second annular sealing device are less than30 m apart, or less than 10 m apart, optionally less than 5 m apart,more optionally less than 2 m, less than lm or less than 0.5 m; andthere is at least one communication path from the well to the reservoirbetween the packer elements.
 31. (canceled)
 32. A method as claimed inclaim 1, wherein the apparatus is deployed into the well in the sameoperation as deploying the annular sealing device into the well.
 33. Amethod as claimed in claim 32, wherein the apparatus is conveyed on oneof tubing, drill pipe and casing/liner. 34.-36. (canceled)
 37. A methodas claimed in claim 1 further comprising conducting a procedure on thewell, wherein the procedure includes at least one of a build-up test,drawdown test, connectivity tests such as one of, an interference testand pulse test, drill stem test (DST), extended well test (EWT),hydraulic fracturing, minifrac, pressure test, flow test, well/reservoirtreatment such as an acid treatment, permeability test, injectionprocedure, gravel pack operation, perforation operation, image capture,string deployment, workover, suspension and abandonment.
 38. A method asclaimed in any claim 1, wherein the well comprises an array of discretetemperature sensors or a distributed temperature sensor.
 39. A method asclaimed in claim 1, wherein the container has a volume of at least 5 lat least 50 l, optionally at least 100 l.
 40. (canceled)
 41. A method asclaimed in claim 1, wherein the well includes casing/liner, and thecontainer takes up the whole cross-section of the casing/liner. 42.(canceled)
 43. A method as claimed in claim 1, wherein in addition tothe container, there is at least one secondary container having a volumeof at least 1 l, the at least one secondary container having a controldevice for controlling communication between the secondary container andthe surrounding portion of one of the well and other portion of theapparatus, wherein the control device includes at least one of amechanical valve and a latch assembly, and wherein at least onesecondary container has a different pressure than a surrounding portionof the well. 44.-55. (canceled)
 56. A method to manipulate a well byconducting a short interval test, comprising: providing a pressuresensor in the well; providing an apparatus in the well, the apparatuscomprising a container having a volume of at least 5 litres and a portto allow fluid and optionally pressure communication between a portionof an inside of the container and an outside of the container; the portof the apparatus being below a first portion of a packer element andabove a second portion of a or the packer element, said portions spacedapart from each other by up to 10 m thus defining a short interval, andeach engaging with an inner face of casing or wellbore in the well, andbeing at least 100 m below a surface of the well; the short intervalincluding at least one communication path between the well and theformation; the apparatus further comprising: a pump adapted to movefluid from the surrounding portion of the well into at least a portionof the container via the port; a control mechanism comprising acommunication device configured to receive a control signal for movingthe valve member; deploying the apparatus into the well on a tubular,sending a control signal from outwith the short interval to the controlmechanism at least in part by a wireless control signal transmitted inat least one of the following forms: electromagnetic, acoustic,inductively coupled tubulars and coded pressure pulsing; operating thepump in response to said control signal to allow fluid to enter thecontainer; and, drawing in at least 5 litres of fluid into the containerfrom the well.